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Influence of Petrophysical Calibrations on

Geomechanics and Resultant effects on

Hydraulic Fracturing: A Case Study.

SPWLA Kuwait Chapter – 17th April 2012

Satya Perumalla GMI Geomechanics Services,

Baker Hughes.

Introduction & Challenges

Geomechanical Setting of the Study Area in North Oman

Hydraulic Fracturing Experience from 2 Deep Gas wells

Geomechanical Investigations

Relation between Petrophysical & Geomechanical

Parameters

Conclusions, Learning & Recommendations

Outline

Introduction & Challenges (1)

• Active development of Paleozoic Amin Deep Tight Gas Sand

Reservoir in Oman.

• Reservoir depth > 5,000 m (16,000 ft) TVD.

• Low porosity: 3 – 7%, Low permeability: 0.001 – 1 mD

• High rock compressive strength: 110 – 250 MPa (15,000 –

35,000 psi).

• High Temperatures: 170° - 190°C

• Deepest well in the Middle East (> 7,000 m TVD).

Introduction & Challenges (2)

• High In-situ stresses High Fracture Gradient

• High Compressive Strength High Tensile Strength

• Structural Compartmentalization: Variable Reservoir

Pressure & Stress orientation in the region Faults.

• Presence of Natural Fractures & proven stress-sensitive

permeability.

• Production from natural fractures is not economical.

• Stimulation / Frakking is a must: for Economic viability.

Geomechanical Setting

• Strike-Slip Stress regime

SHmax >> Sv > Shmin

• Variable Pore Pressure

(Pp): Getting accurate Pp

is a challenge in this tight

formation.

• Extremely strong rocks

experiencing high

stresses.

30-35

kPa/m

~ 17 kPa/m

23-24

kPa/m

11-13

kPa/

m

110 – 250+

MPa

6

Maximum attempted

pressure is higher than

SHmax: Unsuccessful

fracturing attempt

Breakdown pressure:

Successful Fracturing

Pp

MW

Sh

min

Sv

SH

ma

x

Sh

min

+ T

en

sil

e s

tre

ng

th

Pe

rfo

rati

on

s

UCS Static Young’s

modulus (MPa)

Internal

Friction

Poisson’s

ratio

Hydraulic Fracturing Experience (Well # 1)

7

Geomechanical Investigation (Well # 1)

• Successfully Fractured Interval:

• Lowest UCS: 110 MPa possibly lowest Tensile strength.

• Consistent development of stress-induced wellbore failure

(borehole breakouts & tensile fractures)

• Slight over-pressure near the perforation interval

• Mud cooling by 10-15°C ( from 170 – 190°C) how

effective?

• Unsuccessful Interval:

• High UCS ~ 150 MPa possible high Tensile strength /

resistance.

• Inconsistent wellbore failure

• Hydrostatic pore-pressure.

• Same mud cooling as above.

8

Breakouts of ~ 60°

width at

successfully

fractured zone

Un-interpreted Image Interpreted Image

Geomechanical Investigation (Well # 1)

9

KCl attempt NaBr attempt

Attempt 1 Attempt 2

Pp

MW

Sh

min

Sv

SH

ma

x

Sh

min

+

Te

ns

ile

str

Pe

rfo

rati

on

s

UCS

Static Young’s

modulus (MPa)

Internal

Friction

Poisson’s

ratio

UCS

(MPa)

Hydraulic Fracturing Experience (Well # 2)

10

Geomechanical Investigation (Well # 2)

• No successful fracturing despite trying with various

fluids.

• Unsuccessful Intervals:

• Over all UCS of Amin is consistently stronger than Well # 1

More than 150 Mpa High Tensile strength.

• Very limited stress induced wellbore failure.

• Comparable stress magnitudes with Well # 1.

• Hydrostatic pore pressure; no over pressured zones.

11

Amin

Calipers

Geomechanical Investigation (Well # 2)

12

Petrophysics for Geomechanics

• Quality of log properties Borehole conditions, Temperature,

Mud, etc.

• Accuracy of parameter value: challenge in Tight gas

reservoirs.

• Good quality petrophysical parameters (density, porosity,

velocity, etc) Good quality rock mechanical parameters

(UCS, Poisson ratio, Young’s modulus, etc).

• Petrophysical uncertainty Rock mechanical uncertainty

Geomechanical Model uncertainty Decisions!!!

Petrophysics for Geomechanics Conventional

porosity

calibrated UCS

Perforations Perforations

UCS Calibrated

with porosity

derived from Core

Tests

14

Petrophysics for Geomechanics

• Calibration from log to rock mechanical property in multiple

stages:

• Log porosity Calibrate with core porosity & fluid type

Calibrated/Corrected porosity log curve.

• Laboratory UCS Laboratory porosity Corrected

porosity UCS curve.

• Uncertainty in corrected porosity Uncertainty in UCS.

• Uncertainty with UCS Uncertainty with Tensile Strength

• Impact on perforation decisions & Fraccability.

15

Conclusions (1)

Some observations relating Geomechanics to Hydraulic

Fracturing experience.

Well -1:

• The only successful fracturing job at a particular facies

indicated that this interval has significantly lower rock

strength of 110 MPa when compared to most of Amin

formation with average UCS of ~200 MPa.

• Significant presence of stress induced borehole

breakouts and tensile cracks supports that this interval

was a suitable candidate for hydraulic fracturing.

16

Conclusions (2)

Well -1 (continued):

• The Fracture Breakdown Pressure in this facies = Shmin +

Tensile strength: supporting sufficient pressure

contribution through perforation to initiate and propagate

the fracture.

• The other perforated intervals where hydraulic fracturing

was unsuccessful, have shown higher rock strengths of at

least 150-170 MPa, therefore possible higher tensile

strength to offer resistance for fracturing.

17

Conclusions (3)

Well -2:

• Amin in Well-2 is much tighter than in Well-1 with average

UCS of ~ 250 MPa (higher than in Well-1). As a result, the

formation appears to be having much higher tensile

strength to offer high resistance to initiate any hydraulic

fracture.

• Attempted fracturing the weakest interval of Lower Amin in

Well-2 was unsuccessful with similar operational setup as

Well-1.

18

Recommendations for Frac Jobs

• Creating tension in borehole to create tensile cracks with

higher mud cooling efforts. (BHT ~ 190°C)

• Horse Power Optimization using Geomechanics:

• Oriented perforations (sub)-parallel to SHmax (aligning

them with any present tensile cracks) would avoid loss

of pressures into unfavorably oriented perforations: to

enhance the fraccing success chances.

• Perforation interval selection based on lab calibrated

porosity/UCS and stress profiles.

• Placing horizontal wells parallel to Shmin in a weaker

zone and open hole multi-stage fraccing.

19

Recommendations: Field Development

• Mechanical characterization of Amin reservoir: Relationship

among Mechanical properties Mechanical Stratigraphy

Sedimentology. Use Scratch, Brazilian & Triaxial tests To

refine rock properties.

• Variable stress orientation & Pore pressure in North Oman

across fault blocks: Capture geomechanical variability

through: Regional Stress Maps & 3D Geomechanical Models.

• Stage wise coordination, data transfer and analyses are

important between exploration and geomechanics teams in

order to capture most important geomechanical aspects at

each stage of operation in order to provide decision support

for the next stage.

Thanks to You all!

Ministry of Oil & Gas, Sultanate of Oman.

Petroleum Development Oman &

Baker Hughes.

Acknowledgements